Slug flow monitoring and gas measurement

ABSTRACT

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, for monitoring slug flow in subterranean wells. In one aspect, a method includes at a time instant, transmitting an acoustic signal across a cross-section of a pipeline flowing multiphase fluid including gaseous fluid and liquid fluid, wherein a portion of the acoustic signal is carried through the cross-section of the pipeline by the multiphase fluid and determining, at the time instant, a first quantity of the gaseous fluid and a second quantity of the liquid fluid passing the cross-section of the pipeline based, in part, on an energy of the portion of the acoustic signal carried through the cross-section and at least a portion of a total energy of the transmitted acoustic signal.

CROSS-REFERENCE TO RELATED PATENT APPLICATIONS

This application is a divisional of and claims the benefit of priorityto U.S. patent application Ser. No. 15/697,681, filed Sep. 7, 2017,which is a continuation of U.S. patent application Ser. No. 14/626,265,now issued as U.S. Pat. No. 9,778,226 on Oct. 3, 2017, the contents ofwhich are incorporated by reference herein.

TECHNICAL FIELD

This specification relates to flow in subterranean zones from whichhydrocarbons can be recovered.

BACKGROUND

Hydrocarbons, such as oil and gas, can be retrieved from subterraneanzones using a well or a wellbore drilled into the subterraneanformation. In some cases, the wellbore is lined by casing, whichtypically is a hollow steel pipe that is perforated by each productionzone to extract fluids from the subterranean formation. Fluid from eachproduction zone entering the wellbore is drawn into the tubing andguided towards the surface. For example, the fluid moves from thereservoir to the annular space, from where it can flow to an inflowcontrol device and finally to the base pipe. The geometry of thewellbore, such as uneven drainage, can lead to a multiphase flow, due tothe invasion of a gas cone or a water cone. It is common in hydrocarbonwell operations to have two or more types of fluids flowing through adownhole tubular positioned in a wellbore extending through thesubterranean zone. For example, during production, the fluids in thewellbore tend to separate into zones of oil, water, gas and solid (e.g.,sand) flow.

SUMMARY

This specification describes technologies relating to monitoring slugflow in subterranean wells and measuring gas quantities in the slugflow.

Some aspects of the subject matter described here can be implemented asa method including at a time instant, the transmission of an acousticsignal across a cross-section of a pipeline flowing multiphase fluidincluding gaseous fluid and liquid fluid and determining, at the timeinstant, a first quantity of the gaseous fluid and a second quantity ofthe liquid fluid passing the cross-section of the pipeline based, inpart, on an energy of the portion of the acoustic signal carried throughthe cross-section and at least a portion of a total energy of thetransmitted acoustic signal. A portion of the acoustic signal is carriedthrough the cross-section of the pipeline by the multiphase fluid.

This, and other aspects, can include one or more of the followingfeatures. At each subsequent time instant of a plurality of subsequenttime instants a subsequent acoustic signal is transmitted across thecross-section of the pipeline. A portion of the subsequent acousticsignal is carried through the cross-section of the pipeline by themultiphase fluid. A third quantity of the gaseous fluid and a fourthquantity of the liquid fluid passing the cross-section of the pipelineis determined based, in part, on an energy of the portion of thesubsequent acoustic signal carried through the cross-section and anenergy of the transmitted subsequent acoustic signal. A composition ofthe multiphase fluid flowed through the cross-section during the timeinstant and the plurality of subsequent time instants is determined. Thetransmission of the acoustic signal across the cross-section of thepipeline includes attaching an acoustic signal transmitter to a firstlocation on the cross-section of the pipeline and connecting an acousticsignal generator to the acoustic signal transmitter, the acoustic signalgenerator to generate the acoustic signal. The acoustic signaltransmitter is attached to transmit the acoustic signal at a beam angleranging between about 5° and 15°. The acoustic signal transmitter isconfigured to generate an acoustic signal in a frequency range ofbetween about 0.5 MHz and 2.0 MHz. The acoustic signal generator isconfigured to generate and transmit an electric signal to the acousticsignal transmitter, and the acoustic signal transmitter is configured toconvert the electric signal into the acoustic signal. An acoustic signalreceiver is attached to a second location on the cross-section of thepipeline and an acoustic signal evaluator is connected to the acousticsignal receiver. The acoustic signal transmitter and the acoustic signalreceiver are attached at diametrically opposite ends of thecross-section of the pipeline. The acoustic signal includes an amplitudedetermined based on a deviation in pressure from a mean ambientpressure. A first quantity of the gaseous fluid and a second quantity ofthe liquid fluid passing the cross-section of the pipeline aredetermined at the time instant based, in part, on an energy of theportion of the acoustic signal carried through the cross-section and anenergy of the transmitted acoustic signal includes determining an energyof the portion of the acoustic signal carried through the cross-section.

E _(S)=Σ_(n=1) ^(N) |x _(n)|² Δt

In some embodiments, the quantity of the gaseous fluid and the quantityof the liquid fluid passing the cross-section of the pipeline aredetermined, at the time instant, based, in part, on an energy of theportion of the acoustic signal carried through the cross-section. Anenergy of the transmitted acoustic signal includes determining that theenergy of the portion of the acoustic signal carried through thecross-section and the energy of the transmitted acoustic signal aresubstantially equal and determining that multiphase fluid includes moreliquid fluid than gaseous fluid. In some embodiments, the quantity ofthe gaseous fluid and a quantity of the liquid fluid passing thecross-section of the pipeline are determined, at the time instant,based, in part, on an energy of the portion of the acoustic signalcarried through the cross-section. An energy of the transmitted acousticsignal includes: determining that the energy of the portion of theacoustic signal carried through the cross-section is substantially lessthan the energy of the transmitted acoustic signal and determining thatmultiphase fluid includes substantially more gaseous fluid than liquidfluid.

Some aspects of the subject matter described here can be implemented asa system to analyze multiphase fluid in a pipeline. The system includesan acoustic transmitter to attach to a first location of the pipelineflowing multiphase fluid including gaseous fluid and liquid fluid, theacoustic transmitter to transmit an acoustic signal of a first energyacross a cross-section of a pipeline flowing multiphase fluid includinggaseous fluid and liquid fluid. The system also includes an acousticreceiver to attach to a second location of the pipeline, the acousticreceiver to receive a portion of the acoustic signal carried by themultiphase fluid across the pipeline, the portion of the acoustic signalhaving a second energy and an acoustic signal evaluator to determine aquantity of the gaseous fluid and a quantity of the liquid fluid passingthe cross-section of the pipeline based, in part, on the second energyand the first energy.

This, and other aspects, can include one or more of the followingfeatures. The system includes an acoustic signal generator to generatethe acoustic signal. The acoustic signal generator is connected to theacoustic transmitter, wherein the acoustic signal generator isconfigured to generate and transmit an electric signal to the acousticsignal transmitter, and wherein the acoustic signal transmitter isconfigured to convert the electric signal into the acoustic signal.

E _(S)=Σ_(n=1) ^(N) |x _(n)|² Δt

In some embodiments, the acoustic signal transmitter is attached to thefirst location to transmit the acoustic signal at a beam angle rangingbetween about 5° and 15°. The acoustic signal transmitter is configuredto generate an acoustic signal in a frequency range of between about 0.5MHz and 2.0 MHz.

Some aspects of the subject matter described here can be implemented asa method including transmitting an acoustic signal across across-section of a pipeline flowing multiphase fluid including gaseousfluid and liquid fluid, receiving the acoustic signal carried by themultiphase fluid through the cross-section of the pipeline, determiningan energy level of the received acoustic signal and determining flowparameters of the multiphase fluid based, in part, on the determinedenergy level of the received acoustic signal.

This, and other aspects, can include one or more of the followingfeatures. The transmission of the acoustic signal across thecross-section of the pipeline includes the acoustic signal through anacoustic transmitter attached to an outer surface of the pipeline at afirst location, wherein receiving the acoustic signal carried by themultiphase fluid through the cross-section of the pipeline includesreceiving the acoustic signal carried by the multiphase fluid at anacoustic receiver attached to an outer surface of the pipeline at asecond location, and wherein the first location and the second locationare diametrically opposite on the cross-section. The flow parametersinclude at least one of a slug velocity, a slug frequency and a sluglength. The slug velocity is determined based on correlating theacoustic signal received at two locations of the pipeline and a traveltime between the two locations.

The details of one or more embodiments of the subject matter describedin this specification are set forth in the accompanying drawings and thedescription below. Other features, aspects, and advantages of thesubject matter will become apparent from the description, the drawings,and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates an example well system for monitoring slug flow.

FIG. 1B illustrates another example well system for monitoring slugflow.

FIG. 1C illustrates a cross-sectional view of an example well system formonitoring slug flow.

FIG. 2 is a flowchart of an example process for monitoring slug flow.

FIG. 3 is a flowchart of another example process for monitoring slugflow.

Like reference numbers and designations in the various drawings indicatelike elements.

DETAILED DESCRIPTION

This specification relates to monitoring flow in subterranean wells. Thefluid flowing through subterranean wells can include oil, water, gas andsolid (e.g., sand). The coexistence of different types of fluidsgenerates a multiphase flow that implies that fluid composition may varyfrom point to point within the wellbore as a function of pressure,temperature and slip between the phases. The multiphase flow can dependon a number of factors including the relative density ratio of one fluidto the other, difference in viscosity between fluids, and velocity(e.g., slip) of each fluid. The multiphase flow in subterranean wellscan vary during the production life of a well or a group of wells whoseflow is commingled in a common production line. For example, theproduction of gas can increase during the life of an oil-bearingformation, particularly if gas is being used as a drive fluid to forcecrude oil to the production well or wells. In such cases the gasconcentration increases and concentrations of other fluid componentsdecreases.

The multiphase flow often results in so-called slug flow, in which slugsof liquid occur in the flow lines that are connected to the separation,treatment and pumping equipment. The slug flow regime can be encounteredfrequently for a wide range of oil and gas flow rates. Slug flow inliquid-gas compositions can affect the flow line designs and themechanical integrity of the oil production system. Consequently,monitoring slug flow in liquid-gas compositions can be useful.

Implementations of the subject matter described in this specificationare generally directed to multiphase flow monitoring in subterraneanwells. Some implementations include an automatic computation of a set ofproperties of a slug flow in subterranean wells. Slug flow is amultiphase flow that can start with two different phases, in which thegas phase, for instance, exists as large bubbles separated by liquidslugs. In some examples, each gas pocket is followed by a train ofbubbles in the liquid phase that define the slug tail. Slug flow can begenerated inside the wellbore and continue in pipelines, to the surfaceprocessing facilities. Knowledge of slug flow parameters including thefrequency, velocity and length of the slugs can improve the efficientdesign and operation of pipelines.

Particular embodiments of the subject matter described in thisspecification can be implemented so as to realize one or more of thefollowing advantages. The accuracy and reliability of the proposedmethod to monitor the multiphase flow is independent from the amount ofgas void fraction. The method accounts for acoustic variability andnon-stationary nature of the signal. Any of the described methods can becoupled with arrays of sensors so that precursor conditions to sluggingcould be detected and the slugging itself could be prevented. Thedisclosed system engineered as a slug low metering solution can beinstalled either in surface applications as top sides off-shore oron-shore locations and it can also be deployed downhole as part of apermanent or retrievable system. The system characteristics allow forcompact packaging of the metering system and can efficiently function atlow power. The method was designed to be computationally inexpensive andthe system can be developed at a low cost.

As shown in FIG. 1A, an example well system 100 can be implementedduring well production to monitor slug flow in a subterranean formation101. Measurement of slug flow can support the optimization of wellproduction. The example well system 100 includes a wellbore 104 formedwith a drilling assembly (not shown). The drilling assembly can be usedto form a vertical wellbore portion extending from the terranean surface110 and through one or more subterranean formations 106 and/or 108 (orother subterranean formations or zones). The subterranean region caninclude a reservoir 120 that contains hydrocarbon resources, such asoil, natural gas, and/or other hydrocarbon resources. The reservoir 120can include porous and permeable rock containing liquid and/or gaseoushydrocarbons, such as oil, water or other liquids. The reservoir 120 caninclude a conventional reservoir, a non-conventional reservoir, a tightgas reservoir, and/or other types of reservoir. The well system 100produces the resident hydrocarbon resources from the reservoir 120 tothe surface 110 through the wellbore 104.

The wellbore 104 in the well system 100 can include any combination ofhorizontal, vertical, slant, curved, articulated, lateral, multi-lateraland/or other well bore geometries that can affect the fluid flow throughthe wellbore. One or more wellbore casings, such as a conductor casing112, an intermediate casing 114, and a production casing 116 can beinstalled in at least a portion of the vertical portion of the wellbore104 and/or other wellbore portion. Alternatively, in some embodiments,one or more of the casings 112, 114, and 116 cannot be installed (e.g.,an open hole completion).

In some embodiments, the wellbore 104 can include multiplediscontinuities (e.g. perforations, fractures, or otherdiscontinuities). FIG. 1A illustrates exemplary discontinuities 122 andfractures 118. The discontinuities 122 can include a communicationtunnel created from the casing 116 into the reservoir formation 120,through which oil or gas is produced. The geometry of the perforation122 can depend on the method used to create the perforation 122 and canaffect the fluid flow through the wellbore.

In a first embodiment, system 100 includes an acoustic pair formed of atransmitter 124 and a receiver 126. The transmitter 124 and the receiver126 can be attached to the wellbore 104 (e.g., to the production casing116) such that the surface of the transmitter 124 and the surface of thereceiver 126 are in direct contact with the fluid flow. In someimplementations, a non-invasive configuration of the system (where theacoustic transmitter 124 and the receiver 126 pairs are not in directcontact with the fluid flow) can be used. In the non-invasiveconfiguration of the system, the acoustic transmitter 124 and thereceiver 126 pairs can be clamped on the pipeline using a couplantbetween the surface of the transmitter 124 and the wellbore 104 as wellas using a couplant between the surface of the receiver 126 and thewellbore 104, thus forming a removable system that does not affect thestructure of the wellbore 104.

In some implementations, as illustrated in FIG. 1A, the transmitter 124and the receiver 126 can be attached to diametrically opposite ends ofthe cross-section of the pipeline. In some implementations, asillustrated in FIGS. 1A, 1B and 1C, the transmitter 124 and the receiver126 are offset from a cross-section taken perpendicular to alongitudinal axis of the wellbore 104. The transmitter 124-receiver 126pair can be operated to monitor multiphase flow at one time instant orat multiple time instants.

In another embodiment, as illustrated in FIG. 1A, system 100 includes aplurality of acoustic pairs formed of multiple transmitters 124 and acorresponding number of receivers 126. Each acoustic pair has the samecharacteristics as the transmitter 124-receiver 126 pair in the firstembodiment. Each transmitter 124-receiver 126 pair can be attached tothe wellbore 104 at different depths, positions and/or orientations, andcan monitor multiphase flow at one or more time instants. The firstembodiment allows determining a multiphase flow profile across across-section of the pipeline, while the second embodiment allowsdetermining a flow profile across the length of the pipeline.

In some implementations, the transmitter 124 and the receiver 126 can bepositioned on a wellhead to monitor slug flow from a well. Thetransmitter 124 and the receiver 126 can also be deployed downhole,inside a well for slug flow monitoring from wellbore. The transmitter124 and the receiver 126 can be a part of a permanent smart completion,or a retrievable system in motherbore or laterals. The transmitter 124and the receiver 126 can be positioned at an arbitrary angle relative toeach other (for example in this range: 5°-15°). In an extreme casecertain multiphase flows, such as bubbly flow, can produce a strongreflection signal, raising difficulties in co-locating the transmitter124 and the receiver 126 or even use a single transceiver 124 and 126.Coverage of the full range of multiphase flows can require multipleangles of interrogation. Modifying the angular response in particularsituations can result in a more accurate measurement of the flow regime.

The transmitter 124 and receiver 126 can operate at a fixed highfrequency (e.g., in the range: 0.5-2 MHz) with a narrow beam angle (inthis range: 5°-15°). Among different transmitter 124/receiver 126 pairs,one pair can operate at the same or different frequencies than anothertransmitter 124 and receiver 126 pair. The transmitter 124 can transmitan acoustic signal being driven by an electric signal generated by asignal generator 132 and amplified by an amplifier 134. The signalgenerator (e.g., oscillator) 132 can generate a continuous sinusoidalwave signal of high frequency (e.g., 0.5-2 MHz) and low voltage (e.g.,5-10V) characterized by a particular amplitude, frequency and phase. Insome implementations, more complex waveforms can be generated where, forexample, the frequency of the input signal can be chirped from a lowfrequency to a high frequency over a fixed period of time which can beused to cover the frequency space.

A chirp or a sweep signal can be used in which the frequency is sweptlinearly or exponentially from a low frequency (as low as 100 KHz) to ahigh frequency (2 MHz) in a fixed period of time. Such a signal canprovide valuable information about acoustic signal transmission throughthe flow over the full frequency spectrum. The chirp or a sweep signalcan help in improving the accuracy of measurement. A complex processingmethod can be required to extract information from a transmitted sweepsignal. A lower frequency modulation of the signal in kHz or lowerfrequency range can be introduced in the electric signal and lock-inamplifier style measurements can be implemented to filter out noise inthe measurement. The electric signal can be amplified by the amplifier134 (e.g., a high-voltage operational amplifier) to 50-100V. Theamplified electric signal is provided to drive the acoustic transmitter124. The transmitter 124 converts the electric signal to acoustic signaland generates a continuous high-frequency (e.g., 0.5-2 MHz) acousticsignal. In some implementations, the transmission signal strength isincreased to compensate for the attenuation of the acoustic signal inslug flow. The transmission signal strength can be increased byincreasing the gain of the amplifier using a programmable gain amplifierinstead of a fixed gain amplifier 134.

Several types of transmitters 124 can be implemented. One example of atransmitter 124 can be a piezoelectric transceiver (or transmitter) ofsimilar construction to the receiver in which a voltage signal is usedto modulate the sound waves by causing the piezoelectric stack to expandand contract as the electric field is applied across it. A piezoelectrictransceiver can be tuned to a narrow range of frequencies. Anotherexample of a transmitter 124 can be an array of high Q piezoelectrictransceivers (or transmitters) with the resonant frequencies in therange of operation which is nominally 0.5-2.0 MHz. In frequency space, aselection criteria can include that for adjacent transceivers thefrequency associated with the upper −3 dB point of the lower frequencytransceiver coincides with the lower −3 dB point for the higherfrequency transceiver. Adjacent transceivers characterized by theselection criteria can be generate a continuous frequency acousticsignal. The transceivers are smaller than the receiver or receiverarray. A single voltage signal can be inputted which is then routedthrough a parallel array of amplifiers which supply each of thetransceivers in the array individually.

In some examples, the piezoelectric element of the transceivers (ortransmitters), the actuator can be replaced by a magnetrostrictivematerial driven by the magnetic field generated by a surrounding coil.The coil can require a current supply so that a voltage signal can beinputted and fed through a current amplifier to provide a currentsource. The bandwidth of the transceiver 124 can be improved by using anarray of magnetrostrictive transceivers. Another example of transceivers(or transmitters) 124 can include an electromechanical loudspeakersystem, tuned for operation at high frequencies (taking intoconsideration the bandwidth). A non-standard solution can be implementedto modify the operation of the electromechanical loudspeaker system fromkHz regime to MHz regime, such as through MEMS (Microelectromechanicalsystems) based systems with the mass of the elements reduced, beingadapted to operate at the selected frequency ranges. Another example oftransceivers (or transmitters) 124 include an actuation system, whichconverts electrical energy either in the form of voltage or current intosome form of movement in the frequency range of interest (MHz range).

The acoustic signal is transmitted through the slug flow and is receivedby the acoustic receiver 126. The acoustic receiver 126 converts theacoustic signal into an analog electric signal. The analog electricsignal can be pre-amplified by a pre-amplifier 136 (e.g., a fixed gainoperational amplifier). The amplified signal is filtered using aband-pass filter 138. The cutoff frequencies of the band-pass filterdepend on the operating frequency and bandwidth of acoustic transmitter124 and receiver 126. The filtered analog signal is converted to digitalsignal using a high resolution analog-to-digital converter (ADC) 140.The digital signal is transmitted by the ADC 140 to a personal computer(PC) or Digital Signal Processor (DSP) 142 for being processed. ThePC/DSP 142 is powered by a battery 144. The processing results can besaved in a memory 146.

As illustrated in FIG. 1A, the transmitter 124 and the receiver 126 canbe communicably coupled to a computing system 102 through, for example,a wireline 130. The computing system 102 can include the signalgenerator 132, the amplifier 134, the pre-amplifier 136, the band-passfilter 138, the ADC 140, the DSP 142, the battery 144 and the memory146. In some embodiments, as illustrated in FIG. 1B and 1C, thetransmitter 124 is connected to the signal generator 132 and theamplifier 134, while the receiver(s) 126 is separately connected to theelectronic components that process the received acoustic signal. Thereceiver(s) 126 can include logging capabilities to evaluate and/ormeasure properties of the slug flow, including quantity and compositionof the fluid flowing through the well 128. The measurements can be madedownhole, stored in solid-state memory for some time and latertransmitted to the computing system 102 (e.g., for storage and/oranalysis). In some embodiments, the received acoustic signal can betransmitted and/or transferred real-time to a surface processing system,including the pre-amplifier 136, the band-pass filter 138, the ADC 140,the DSP 142, the battery 144 and the memory 146 (e.g., over the network130). For example, as illustrated, such properties can be stored as flowproperties in the illustrated memory 146.

The transmitter 124 includes a transducer, which converts acoustic toelectrical energy. The receiver 126 includes a transducer, whichconverts electrical to acoustic energy. As the acoustic transducers (thetransmitter 124 and the receiver 126) are in acoustic contact with theliquid, a first quantity of acoustic energy can be transmitted from thetransmitter 124 to the receiver 126 through a fluid without gas that isflowing through the wellbore 104. A second quantity of acoustic energy,which is smaller than the first quantity of acoustic energy can betransmitted from the transmitter 124 to the receiver 126 through a fluidformed of a mixture of gas and liquid that is flowing through thewellbore 104. A third quantity of acoustic energy, which is smaller thanthe second quantity of acoustic energy can be transmitted from thetransmitter 124 to the receiver 126 through a fluid formed of gas thatis flowing through the wellbore 104. For example, a maximum acousticenergy passes through the fluid when no gas (e.g., air or other gas) ispresent within the wellbore and the medium flowing through the wellboreis completely liquid and no acoustic energy can pass through passesthrough a fluid substantially consisting of gas (e.g., air or othergas). Since acoustic impedance of air (˜400 rayl) is very different thanthat of crude oil (1.3 megarayl) or water (1.48 megarayl at 20°C.),liquid-air interface acts as a reflector that scatters and reflects theincoming acoustic wave in the presence of air bubbles in liquid. Suchscattering and/or reflection introduces reverberations and acousticenergy loss. For example, when an elongated bubble is passing betweenthe acoustic transmitter 124 and the receiver 126, a significantmajority of the transmitted acoustic energy is reflected by liquid/airinterface and no signal can be received by the acoustic receiver 126.

FIG. 2 is a flow chart showing an example process 200 for monitoringmultiphase flow. In some instances, the process 200 is used to monitorslug flow to assist the production of fluids in a wellbore. At 202, oneor more acoustic signal transmitters are attached to a first location onthe cross-section of the pipeline. The acoustic signal transmitter canbe placed at any location where measurement of slug flow is required.For example, the acoustic signal transmitter can be located at surfaceor downhole. At surface, the location can be before the downstreamprocessing equipment (so that the operation of the processing equipmentcan be accordingly designed). At 204, the acoustic signal transmitter isconnected to a signal generator. At 206, an acoustic signal can begenerated. For example, the acoustic signal can be generated by anacoustic transmitter (e.g., transmitter 124 in FIGS. 1A-1C). At 208, theacoustic signal can be transmitted at a time instant or at multiple timeinstants across a cross-section of a pipeline, though which a multiphasefluid is flowing. The multiphase fluid can include gaseous fluid andliquid fluid that can carry at least a portion of the acoustic signalthrough the cross-section of the pipeline. In some implementations, asubsequent acoustic signal is transmitted across the cross-section ofthe pipeline.

At 210, a portion of the acoustic signal can be received at a timeinstant or at multiple time instants by an acoustic signal receiver,attached to a second location on the cross-section of the pipeline thatis connected to an acoustic signal evaluator. The received acousticsignal includes an amplitude determined based on a deviation in pressurefrom a mean ambient pressure. At 212, a quantity of the gaseous fluidand a quantity of the liquid fluid passing the cross-section of thepipeline can be determined at a time instant. In some implementations,the quantity of the gaseous fluid and the quantity of the liquid fluidpassing the cross-section of the pipeline can be determined by acomputing system (e.g., the computing system 102 in FIG. 1A). Thequantity of the gaseous fluid and the quantity of the liquid fluid canbe determined based, in part, on an energy of the portion of theacoustic signal carried through the cross-section and an energy of thetransmitted acoustic signal. The quantity of the gaseous fluid and thequantity of the liquid fluid passing the cross-section of the pipelinebased, can be determined in part by determining that the energy of theportion of the acoustic signal carried through the cross-section and theenergy of the transmitted acoustic signal are substantially equal and bydetermining that multiphase fluid includes more liquid fluid thangaseous fluid. The energy of a continuous-time acoustic signal x(t) canbe defined as:

E _(S)=(x(t),x(t))=∫_(−∞) ^(∞) |x(t)|² dt

The energy of an acoustic signal can be determined using a PC/DSP (e.g.,the computing system 102 in FIG. 1A) that can process the followingequation:

$E_{S} = {\sum\limits_{n = 1}^{N}{{x_{n}}^{2}\Delta \; t}}$

-   -   wherein, E_(S) is the energy of the portion of the acoustic        signal carried through the cross-section, Δt is a sampling        interval, and x_(n) is voltage and n is a sample number. The        measurement takes place starting at a time t=0 with a sampling        interval of Δt including a total of N measurements and the        voltage can be expressed as:

x _(n) =x(n.Δt), 1≤n≤N

The energy can be computed for every 1000 cycles of the receivedacoustic signal. For a system (transmitter and receiver) operating inthe range of 0.5-2 MHz at a central frequency of 1 MHz, the energy canbe computed for every 1000 cycles, which is equal to 1000 energymeasurements per second. Every fifty measurements can be averagedtogether, which results in twenty averaged measurements per second. Insome implementations, a user interacting with the computing systemthrough a GUI can select the averaging parameters.

At 214, a composition of the multiphase fluid flowing through thecross-section during the time instant and the plurality of subsequenttime instants can be determined at a time instant. In someimplementations, the composition of the multiphase fluid can bedetermined by a computing system (e.g., the computing system 102 in FIG.1A). For example, in a two-phase flow, an approximate measurement ofliquid hold up can also be determined from the energy of the receivedacoustic signal. The energy of the received acoustic signal can bestored as a time series of data points E_(S). It is possible to performa Fourier Transform over a sufficiently long measurement window greaterthan the period of the slugs. The Fourier Transform can convert the timeseries of energy measurements E_(S) into a frequency spectrum of datapoints in units of energy per root Hertz and it can be defined asE_(Sm). The index m represents a measurement taking place every 0.001 susing the parameters above. The characteristic frequencies of the slugflow can manifest as one or more frequency peaks within the frequencyspectrum generated by the Fourier Transform. Such peaks can be detectedeither through simple thresholding or through more complex peak fittingalgorithms such as Gaussian peak finding algorithms.

Successive spectra can be obtained either through continuous acquisitionof a moving sampling window, or through successive acquisitions ofenergy data. The evolution of the slugging frequency spectrum can bemonitored as a function of time. Peak tracking algorithms can be used tomonitor the evolution of the slug flow as a function of time. Anacoustic signal that passed through a liquid without gas has maximumacoustic energy, which can be equaled to a normalized value of one,corresponding to zero loss. The energy of the received acoustic signalfor the 100% liquid case can be defined as:

E _(max)=max(E _(Sm))

The energy of the received acoustic signal decreases with increasedamount of gas. In case the entire region between the transmitter and thereceiver is filled with gas, the energy of the received acoustic signalis reduced to zero and the loss is maximum (normalized to one). In anyintermediate state, in which the fluid between the transmitter and thereceiver includes a mixture of liquid and gas, the energy is betweenzero and one. The energy of the received acoustic signal for anyintermediate state can be plotted over time and computed using thefollowing relation:

$E_{S,{normalized}} = \frac{E_{Sm}}{E_{\max}}$

The energy of the received acoustic signal and the loss can be used todetermine the composition of the fluid in the wellbore, such as the gasvolume fraction. To compute the value indicating the gas fraction, thequantity:

1−E_(S,normalized)

is calculated. The normalized energy of the received acoustic signal canexhibit a monotonic dependency with respect to the gas fraction in themeasurement. Through experimentation, the dependency can be calibratedto provide an estimate of the amount of gas in the flow.

The calculation of the composition of the fluid in the wellbore can alsoinclude the geometry of the wellbore. In some implementations, thecomputing system (e.g., the computing system 102 in FIG. 1A) can averagethe determined parameters over a longer period of time, such as 20-30 ormore measurements, and consequently increase the accuracy of the energymeasurement and determination of fluid composition. Process 200 can beincluded in training algorithms and optimization of flow controlhardware, which can minimize flow. Process 200 can also be coupled witharrays of sensors so that precursor conditions to slugging could bedetected and the slugging itself could be prevented.

FIG. 3 is a flow chart showing an example process 300 for monitoringslug flow. At 302, an electric signal can be generated by a signalgenerator (e.g., signal generator 132 in FIG. 1B). At 304, the electricsignal is converted into an acoustic signal and is transmitted across across-section of a pipeline, though which a multiphase fluid is flowing.The signal conversion and transmission of the acoustic signal across thecross-section of the pipeline can include transmitting the acousticsignal through an acoustic transmitter attached to an outer surface ofthe pipeline at a first location (as illustrated in FIG. 1A).

At 306, the acoustic signal is received by an acoustic receiver. Thereception of the acoustic signal carried by the multiphase fluid throughthe cross-section of the pipeline can include receiving the acousticsignal carried by the multiphase fluid at an acoustic receiver attachedto an outer surface of the pipeline at a second location that isdiametrically opposite on the cross-section from the first location. At308, the energy level of the received acoustic signal is determined by acomputing system (e.g., the computing system 102 in FIG. 1A). At 310 theflow parameters in the wellbore are determined by the computing system(e.g., the computing system 102 in FIG. 1A). The flow parameters caninclude the include frequency, velocity and length of the slugs.

In some implementations, the flow parameters can be determined based onthe length of liquid slug body LS and length of elongated bubble LB. Thelength of liquid slug body LS and length of elongated bubble LB can becalculated from a time-energy plot. The total length of a cell isconsidered as being: LS+LB. The frequency of the slug can be calculatedusing the formula 1/(LS+LB). For a system configuration including atleast two acoustic transmitter-receiver pairs (as illustrated in FIG.1A), which are located at a distance of d from each other, the velocityof slug flow can be calculated by correlating the acoustic signalreceived by two pairs and calculating the time it takes for a slug totravel from one acoustic pair to other (Δt). The slug velocity can becalculated using the formula v=d/Δt. In some implementations, a similarcorrelation method can be applied to compute the slug velocity using alinear array transducer that receives a separate signal at the first andlast element. In some implementations, the determined flow parameterscan also include relative density ratio of one fluid to the other,difference in viscosity between fluids and velocity (slip) of eachfluid.

Embodiments of the subject matter and the operations described in thisspecification can be implemented in digital electronic circuitry, or incomputer software, firmware, or hardware, including the structuresdisclosed in this specification and their structural equivalents, or incombinations of one or more of them. Embodiments of the subject matterdescribed in this specification can be implemented as one or morecomputer programs, i.e., one or more modules of computer programinstructions, encoded on computer storage medium for execution by, or tocontrol the operation of, data processing apparatus.

What is claimed is: 1-12. (canceled)
 13. A system to analyze multiphasefluid in a pipeline, the system comprising: an acoustic transmitter toattach to a first location of the pipeline flowing multiphase fluidcomprising gaseous fluid and liquid fluid, the acoustic transmitter totransmit an acoustic signal of a first energy across a cross-section ofa pipeline flowing multiphase fluid comprising gaseous fluid and liquidfluid; an acoustic receiver to attach to a second location of thepipeline, the acoustic receiver to receive a portion of the acousticsignal carried by the multiphase fluid across the pipeline, the portionof the acoustic signal having a second energy; and an acoustic signalevaluator to determine a quantity of the gaseous fluid and a quantity ofthe liquid fluid passing the cross-section of the pipeline based, inpart, on the second energy and the first energy.
 14. The system of claim13, further comprising an acoustic signal generator to generate theacoustic signal, wherein the acoustic signal generator is connected tothe acoustic transmitter, wherein the acoustic signal generator isconfigured to generate and transmit an electric signal to the acousticsignal transmitter, and wherein the acoustic signal transmitter isconfigured to convert the electric signal into the acoustic signal.$E_{S} = {\sum\limits_{n = 1}^{N}{{x_{n}}^{2}\Delta \; t}}$ 15.The system of claim 13, wherein the acoustic signal transmitter isattached to the first location to transmit the acoustic signal at a beamangle ranging between about 5° and 15°.
 16. The system of claim 13,wherein the acoustic signal transmitter is configured to generate anacoustic signal in a frequency range of between about 0.5 MHz and 2.0MHz.
 17. A method comprising: transmitting an acoustic signal across across-section of a pipeline flowing multiphase fluid comprising gaseousfluid and liquid fluid; receiving the acoustic signal carried by themultiphase fluid through the cross-section of the pipeline; determiningan energy level of the received acoustic signal; and determining flowparameters of the multiphase fluid based, in part, on the determinedenergy level of the received acoustic signal.
 18. The method of claim17, wherein transmitting the acoustic signal across the cross-section ofthe pipeline comprises transmitting the acoustic signal through anacoustic transmitter attached to an outer surface of the pipeline at afirst location, wherein receiving the acoustic signal carried by themultiphase fluid through the cross-section of the pipeline comprisesreceiving the acoustic signal carried by the multiphase fluid at anacoustic receiver attached to an outer surface of the pipeline at asecond location, and wherein the first location and the second locationare diametrically opposite on the cross-section.
 19. The method of claim17, wherein the flow parameters comprise at least one of a slugvelocity, a slug frequency and a slug length.
 20. The method of claim19, wherein the slug velocity is determined based on correlating theacoustic signal received at two locations of the pipeline and a traveltime between the two locations.